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July 24, 2008

Range Announces Second Quarter Results

by Sam Savage

RANGE RESOURCES CORPORATION (NYSE: RRC) today announced second quarter results. Range reported its 22nd consecutive quarter of sequential production growth with 381 Mmcfe per day reported for the second quarter. Production increased 22% versus the prior year and 3% over first quarter results. The increase was driven by exceptional drilling results across the Company's core properties, which more than offset significant gas curtailments. Oil and gas sales, including cash-settled derivatives, a non-GAAP measure, reached $313 million, a 42% increase over the prior year. Cash flow from operations before changes in working capital, a non-GAAP measure, rose 41% to $221 million. The reported net loss of $35 million included non-cash charges of $164 million for the mark-to-market accounting on open commodity derivatives, $16 million of non-cash stock expense and a $1 million loss on property sales. Adjusting for these items, net income comparable to analyst estimates was $75 million, or diluted earnings per share of $0.48, 17% greater than the prior year (see the accompanying tables reconciling these non-GAAP measures). The Company's cash flow for the quarter equaled the average of analyst estimates. The adjusted earnings per share of $0.48 were less than the $0.54 average analyst estimate due to the reduction in leasehold value from expiring acreage.

Commenting on the announcement, John Pinkerton, Range's President and CEO, said, "Despite pipeline curtailments that averaged 18.5 Mmcfe per day for the quarter in the Barnett Shale play, our operations teams did a tremendous job driving up production to achieve our 22nd consecutive quarter of sequential production growth. We continue to be on track to achieve our 19% production growth target for the year. Our diversified portfolio of quality drilling projects and our highly focused operating teams are the keys to our success. Importantly, we continue to make solid progress with our emerging plays, building infrastructure, drilling successful delineation wells and increasing our acreage positions. Looking forward, we are extremely well positioned, as our multi-year drilling program is generating excellent returns and our emerging plays provide the opportunity for sustained double digit growth for many years to come."

For the quarter, production totaled 381 Mmcfe per day, comprised of 304 Mmcf per day of gas (80%) and 12,795 barrels per day of oil and liquids. Wellhead prices, including cash-settled derivatives, averaged $9.03 per mcfe, a 17% increase over the prior-year period. The average gas price was $8.46 per mcf, a 16% increase, and the average oil price rose 21% to $72.34 a barrel. If the mark-to-market of the Company's open commodity derivatives were valued as of the close of the market today, the $164 million mark-to-market loss would be completely eliminated.

Direct operating expenses for the quarter were $1.05 per mcfe, $0.20 per mcfe higher than the prior-year quarter and $0.09 greater than the first quarter of 2008. Second quarter direct operating costs were $0.09 higher due to workovers and other activities focused on overcoming the shut-in production. Exploration expense in the second quarter totaled $18 million, up from $11 million in the prior-year quarter due primarily to higher seismic expenditures. General and administrative expenses were $0.49 per mcfe, an increase of $0.05 from the prior-year quarter and $0.11 higher than the first quarter of 2008 due to higher personnel costs, in particular, those incurred in anticipation of the ramp up of Marcellus Shale drilling and production which will not be realized until early 2009. Interest expense rose to $24 million compared to $18 million in the prior-year quarter, due to higher debt outstanding and the refinancing of floating bank debt to longer term fixed rate debt. Depreciation, depletion and amortization rose to $2.24 per mcfe, versus $1.81 in the prior-year quarter due to higher depletion rates and valuation adjustments to the Company's growing leasehold inventory. Depreciation, depletion and amortization was $0.12 higher than the Company's guidance for the quarter due to $0.15 of leasehold amortization, due primarily to expiring acreage.

Second quarter development and exploration expenditures totaled $218 million, funding the drilling of 180 (136 net) wells and 18 (11 net) recompletions. A 99% success rate was achieved with 178 (135 net) wells productive. In the first six months, 264 (200 net) of the newly drilled wells had been placed on production, with the remainder in various stages of completion or waiting on pipeline connection. In addition, $45 million was spent on acreage, $11 million on expanding gas gathering systems and $23 million on property acquisitions. Drilling activity in the third quarter remains high with 30 rigs currently running. During the second quarter, Range also continued to expand several of its key drilling areas and emerging plays as 150,000 acres of new leasehold were acquired or under contract.

During the second quarter 2008, Range's Appalachian division continued to focus on its key coal bed methane and shale drilling projects in Virginia with 64 wells drilled. In the Nora field in Virginia, the division drilled 37 coal bed methane wells on 60-acre spacing and eight infill wells on 30-acre spacing. In addition, Range drilled 17 tight gas sand wells in Nora during the quarter, achieving higher than expected initial production results. The initial horizontal Huron Shale well drilled in late 2007 continues to produce in line with expectations, and the first two horizontal shale wells drilled in 2008 of a 10-well program planned had initial in-line production rates of 1.2 and 0.5 Mmcfe per day. Due to mechanical problems, the lower-rate well had a shorter lateral, but given the length, the rate appears to be proportional. If the Huron program is successful, it will de-risk about 1.5 Tcf of net gas reserves to Range by year-end. The Nora area is one of the largest coal bed methane accumulations in the Appalachian Basin with more than 1,800 producing CBM wells and more than 2,400 remaining locations to be drilled based on 60-acre spacing. If downspacing of coal bed methane and tight gas sand wells are included, the number of remaining locations could exceed 6,000 excluding the shale development.

In the Appalachian Basin Marcellus Shale play, the Company continues its delineation drilling and leasing efforts. At the May update, our acreage position in the Marcellus trend totaled 1.15 million net acres with 700,000 net acres considered very prospective. This position has since expanded to 1.4 million net acres, of which approximately 850,000 acres have been high-graded for further evaluation. Currently, we have three rigs drilling Marcellus Shale wells with plans to add two fit-for-purpose rigs in 2009. Preliminary planning for 2009 includes increasing to eight rigs. To date, 25 horizontal shale wells have been drilled, of which 22 have been completed. During the second quarter, Range completed seven horizontal shale wells in the Marcellus which had initial production rates averaging 4.9 Mmcfe per day. Three of these horizontal wells were significant "step-outs" which have proven up additional acreage. The 4.9 Mmcfe per day average test rate for the most recent seven wells compares to 4.1 Mmcfe per day for the 10 previously announced horizontal wells. Based on the results to date, Range estimates that the gross average reserves per horizontal well are in the range of 3 to 4 Bcfe. In a development mode, Range anticipates that a typical Marcellus horizontal well will cost $3 to $4 million. Based on results to date, estimated finding and development costs range from $0.90 to $1.60 per mcfe. Range has revised upward its estimate of the unrisked reserve potential of its leasehold position to 15 to 22 Tcfe. The Company also recently announced a midstream and infrastructure agreement with MarkWest Energy Partners, L.P. to construct and operate pipelines and processing facilities. Range has secured firm transportation capacity on interstate carriers totaling 150 Mmcf per day and expects to expand this capacity as the play develops. Production will be phased in, but is expected to reach 30 Mmcfe per day in the first quarter of 2009. Parties wishing to lease their property should call Range's land department in Pittsburgh at 724-743-6700.

In the North Texas Fort Worth Basin, the second quarter was highlighted by the completion of four new wells with combined test rates of 33 (25 net) Mmcfe per day. While production for the quarter was severely impacted by pipeline curtailments, two pipeline expansion projects by third parties are anticipated to be completed late in the third and fourth quarters. In Hood County, we have significantly reduced our drilling and completion costs. Our most recent three wells took 10 days from spud to rig release and will be completed for approximately $1.6 million per well, providing excellent finding and development costs of about $0.80 per mcfe. Additional testing in Ellis and Hill counties is continuing. Production from the Moore #2 in Ellis County is nearly identical to the Moore #1 well (approximately 1.5 Mmcfe per day) but was drilled in significantly less time. A third well is planned using a different completion technique in an attempt to improve well economics. In Hill County, we continue to devise and test different completion techniques. Encouragingly, our most recent well is producing 2.4 Mmcfe per day.

Second quarter activity for the Midcontinent division included the drilling of 24 (21 net) wells with a 96% success rate. Texas Panhandle Granite Wash drilling resulted in three completions with combined rates of 5.9 (4.0 net) Mmcfe per day. One additional well is awaiting pipeline connection, and two wells are flowing back fracture stimulations prior to connection. The Ardmore Basin Woodford play also encountered positive results. A horizontal Woodford well was turned to sales flowing 3.0 (1.2 net) Mmcfe per day. Three additional Woodford completions are expected to commence sales within the next few weeks. Drilling activity also continues in the deep Anadarko Basin, Watonga/Chickasha Trend, and the northern Oklahoma shallow play with one rig remaining active in each area. Over 98 (80 net) wells are planned for the Midcontinent region in 2008. In the Gulf Coast division, the Thornhill #3, located in Mississippi, targeting a Hosston sand recently came online and is producing 5.0 (3.6 net) Mmcfe per day.

Conference Call Information

The Company will host a conference call on Thursday, July 24 at 1:00 p.m. ET to review these results. To participate in the call, please dial 877-407-8035 and ask for the Range Resources second quarter financial results conference call. A replay of the call will be available through July 31 at 877-660-6853. The account number is 286 and the conference ID for the replay is 291380. Additional financial and statistical information about the period not included in this release but to be presented in the conference call will be available on our home page at www.rangeresources.com.

A simultaneous webcast of the call may be accessed over the Internet at www.rangeresources.com or www.vcall.com. To listen, please go to either website in time to register and install any necessary software. The webcast will be archived for replay on the Company's website for 15 days.

Non-GAAP Financial Measures and Supplemental Tables:

Second quarter 2008 results included several non-cash items. A $164 million non-cash mark-to-market loss on unrealized derivatives, a $7 million expense recorded for the mark-to-market in the deferred compensation plan, a $1 million loss from property sales and $9 million of non-cash stock compensation expense were recorded. Excluding these items, net income would have been $75 million or $0.50 per share ($0.48 fully diluted). Excluding similar non-cash items from the prior-year quarter, net income would have been $61 million or $0.42 per share ($0.41 fully diluted). By excluding these non-cash items from our earnings, we believe we present our earnings in a manner consistent with the presentation used by analysts in their projection of the Company's earnings (see accompanying table for calculation of these non-GAAP measures).

Range has reclassified within total revenues its financial reporting of the cash settlement of its commodity derivatives. Under this presentation those hedges considered "effective" under SFAS No. 133 (Appalachia oil and gas hedges and Southwest oil hedges) are included in "Oil and gas sales" when settled. For those hedges designated to regions where the historical correlation between NYMEX and regional prices is "non-highly effective" (Southwest gas) or is "volumetric ineffective" due to sale of the underlying reserves (Gulf Coast oil and gas), they are deemed to be "derivatives" and the cash settlements are included in a separate line item shown as "Derivative fair value income (loss)" in Form 10-Q along with the change in mark-to-market valuations of such unrealized derivatives. The Company has provided additional information regarding oil and gas sales in a supplemental table included with this release, which would correspond to amounts shown by analysts for oil and gas sales realized, including cash-settled derivatives.

Under GAAP, due to the sale of all the Company's Gulf of Mexico properties at the end of the first quarter of 2007, all Gulf of Mexico operations during the first quarter 2007 were reclassified to "Discontinued operations" in the reported GAAP financial statements. The Company has presented a supplemental table which reconciles these reported GAAP financial amounts to the amounts if the operations of the Gulf of Mexico properties for the 2007 period were combined with the amounts from the continuing operations. The Company believes that the combined results, by including the Gulf of Mexico properties, corresponds to the methodology used by professional research analysts and, therefore, are useful in evaluating operational trends of the Company and its actual historical performance relative to other oil and gas producing companies by investors in making investment decisions (see the reconciliation of reported continuing operations under GAAP to the combined operations, a non-GAAP presentation in the accompanying table).

"Cash flow from operations before changes in working capital" as defined in this release represents net cash provided by operations before changes in working capital and exploration expense adjusted for certain non-cash compensation items. Cash flow from operations before changes in working capital is widely accepted by the investment community as a financial indicator of an oil and gas company's ability to generate cash to internally fund exploration and development activities and to service debt. Cash flow from operations before changes in working capital is also useful because it is widely used by professional research analysts in valuing, comparing, rating and providing investment recommendations of companies in the oil and gas exploration and production industry. In turn, many investors use this published research in making investment decisions. Cash flow from operations before changes in working capital is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operations, investing, or financing activities as an indicator of cash flows, or as a measure of liquidity. A table is included which reconciles net cash provided by operations to cash flow from operations before changes in working capital as used in this release. On its website, the Company provides additional comparative information on prior periods.

RANGE RESOURCES CORPORATION (NYSE: RRC) is an independent oil and gas company operating in the Southwestern, Appalachian and Gulf Coast regions of the United States.

Except for historical information, statements made in this release, including those relating to anticipated reserve potential, production, drilling results, capital expenditures, the number of wells to be drilled, future realized prices and financial results are forward-looking statements as defined by the Securities and Exchange Commission. These statements are based on assumptions and estimates that management believes are reasonable based on currently available information; however, management's assumptions and the Company's future performance are subject to a wide range of business risks and uncertainties and there is no assurance that these goals and projections can or will be met. Any number of factors could cause actual results to differ materially from those in the forward-looking statements, including, but not limited to, the volatility of oil and gas prices, the costs and results of drilling and operations, the timing of production, mechanical and other inherent risks associated with oil and gas production, weather, the availability of drilling equipment, changes in interest rates, litigation, uncertainties about reserve estimates, and environmental risks. The Company undertakes no obligation to publicly update or revise any forward-looking statements. Further information on risks and uncertainties is available in the Company's filings with the Securities and Exchange Commission, which are incorporated herein by reference.

Range's internal estimates of reserves may be subject to revision and may be different from estimates by our external reservoir engineers at year-end. Although we believe the expectations and forecasts reflected in these and other forward-looking statements are reasonable, we can give no assurance they will prove to have been correct. They can be affected by inaccurate assumptions or by known or unknown risks and uncertainties. The Securities and Exchange Commission permits oil and gas companies, in filings made with the Securities and Exchange Commission, to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. We use certain terms, such as "probable,""possible,""potential" or "unproven," that the SEC's guidelines strictly prohibit us from including in filings with the SEC. These estimates are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of being actually realized by the Company. While we believe our calculations of unproven drill sites and estimation of unproven or potential reserves are reasonable, such calculations and estimates have not been reviewed by third-party engineers. Investors are urged to consider closely the disclosure in our most recent Annual Report on Form 10-K, available from our website at www.rangersources.com or by written request to 100 Throckmorton Street, Suite 1200, Fort Worth, Texas 76102. You can also obtain this form from the SEC by calling 1-800-SEC-0330.